The statements in this section merely provide background information related to the present disclosure and may not constitute prior art.
Historically, the prices of a large number of fossil fuels such as crude oils and refined products have been set either by oil producing countries or determined by the spot market. The Organization of Petroleum Export Countries (OPEC) official selling price system for all intents and purposes ruled the crude oil market from the early 1970's to 1985. Under the OPEC price system, most crude oil sales were transacted as part of long-term contracts having fixed prices and volumes, with price adjustments made infrequently. However, over the years, more crude oil trade has taken place using spot and futures prices and contract sales have entailed shorter durations and more flexible terms.
Spot pricing has become widely accepted in energy markets since the U.S. opted to deregulate energy prices about 30 years ago. Under the spot pricing system, many different crude oil prices are set differentially to the price of one or more benchmarks. Crude oil benchmarks (also known as “markers”) were introduced in the mid 1980's. Most term contracts are now linked to the spot prices of benchmark crude oils, rather than priced at an outright level.
The use of futures and options contracts for energy commodities became more popular in the 1980's, more than a century after commodity exchange trading commenced in the U.S. and Europe. Futures contracts enable owners of assets to obtain price protection against adverse price movements. The buyer is obligated to purchase an asset (or the seller to sell an asset) at a predetermined future date and price. Futures contracts specify the quality and quantity of the underlying asset and are standardized to facilitate trading on exchanges that are typically registered with and regulated by one or more governmental organizations.
While holders of futures contracts are obligated to buy or sell the underlying asset at expiration, an options contract gives the holder the right to buy or sell. Thus, options can be a used as means to hedge futures contracts.
Whereas futures and options contracts are traded over a centralized exchange, another form of hedging involving use of over-the-counter (OTC) derivatives agreements has gained popularity, albeit amid mounting controversies and closer scrutiny from government regulators, as well as the population at large. OTC derivatives are bilateral contracts whereby two parties agree on how a particular trade is settled in the future, with the 3 most common contract types being:    Forwards: agreements to exchange at some fixed future date a given quantity of a physically delivered commodity for a currently defined price.    Swaps: financial agreements settled by cash rather than any transfer of the underlying commodity, which provides price protection for an agreed quantity of a commodity on an agreed future date (usually greater than one month but less than 2 years after the trade date).    Spreads: agreements designed to allow producers to lock in differentials between commodity prices at different times (“calendars”) or between different commodities (“cracks”); in either case, the purchaser/producer pays a pre-agreed fixed spread level in exchange for a floating spread level obtained from the provider in transactions that are usually financially settled.
Most OTC derivatives involve the use of intermediary banks, rather than any centralized exchange, to serve as counterparties matching buyers with sellers. In the process of becoming prominent (if not dominant) OTC derivatives dealers, some of the world's largest banks stand accused of making markets that lack transparency (i.e., in terms of price discovery, volume and counterparty risk) in order to generate large profits at the risk of incurring major losses in the event that counterparties fail to honor their committed trade obligations.
OTC derivatives drew heavy criticism in the aftermath of the Enron scandal of about 2001 and more recently came under even closer scrutiny as the unbridled proliferation of Credit Default Swaps and other OTC instruments led to the demise of Bear Stearns, Lehman Brothers, AIG et al, as well as the ensuing financial crisis that morphed into the Great Recession. As a result, several regulatory initiatives have emerged globally to alter the future of OTC derivatives use. The goal of these regulatory initiatives is to ensure that private contracts between counterparties will become transparent instruments settled by central clearinghouses imposing stricter margin policies to enhance credit risk management and publish more fulsome order, price and volume data.
Major regulatory initiatives on the docket include the Dodd-Frank Wall Street Reform and Consumer Protection Act and similar measures being pursued outside the U.S.; more rigorous capital, leverage and liquidity standards from the Basel Committee on Banking Supervision; and International Financial Reporting Standard No. 9 promulgated by the International Accounting Standards Board. The initiatives call for, inter alia, substantial changes in classifying and measuring financial instruments, the wider use of “mark-to-market” rules and increased hedge accounting and disclosure requirements, as well as for the instruments to be centrally cleared and settled by qualified clearinghouses imposing margin rules. In all likelihood, such initiatives will intensify regulatory capital pressures on banks and affect the ability of, and the means by which, banks maintain their liquidity. As a result, some banks will undoubtedly be curtailed if not precluded from dealing in OTC derivatives and in that process the types traded in the past may become less liquid and thus less attractive to trade.
In most cases involving exchange-traded energy futures and options, as well as OTC derivatives, benchmarks indicate crude oil quality and geographic location. They are useful referencing tools for buyers and sellers because there are so many varying grades of crude oil produced throughout the world. According to the International Crude Oil Market Handbook published by the Energy Intelligence Group, there are around 200 crude oil blends produced in 46 countries, all varying in terms of characteristics, quality and market penetration. Following are the most common crude oil benchmarks used in global commerce:    West Texas Intermediate (WTI) is light sweet crude oil with 39.6° American Petroleum Institute (API) gravity, 0.24% sulfur content and a delivery point in Cushing, Okla. (USA). Although WTI is a U.S. grade of crude oil, it has attained global benchmark status, inter alia because WTI futures and options contracts amassed substantial trading volume gains in the past decade or so from speculators and financial investors around the world. In addition to being a spot market bench-mark, WTI futures and options trade in denominations of 1,000 barrels per contract at the CME Group Nymex (formerly New York Mercantile Exchange) and at the Intercontinental Exchange (ICE) in London.    Brent is comprised of five (5) light sweet crude oil grades with blended API gravity of 38.06° and 0.37% sulfur content. Sourced from the North Sea and refined mostly in NW Europe, Brent is also touted as a global benchmark, in particular for large tanker shipments heading west to N. America from Europe, Africa and the Middle East. Brent futures and options are primarily traded at the ICE in denominations of 1,000 barrels per contract. Prior to September 2010, there were typically fairly small WTI-Brent price differentials (+/−$3 per barrel, with WTI usually exceeding Brent due to higher quality API gravity and lower sulfur content). However, in late 2010, differentials diverged from the previous norm, expanded and eventually exceeded $18 per barrel in March 2011—with Brent exceeding WTI—due to a variety of factors detailed later herein, all of which has prompted concerns about the extent to which Brent and WTI will be able to maintain their status as global benchmarks.    DME Oman Crude Oil futures and options are listed at the Dubai Mercantile Exchange (DME; a collaborator and affiliate of the CME Group), traded in denominations of 1,000 barrels per contract and specified as having API gravity of 31.0°, 2.0% sulfur content and a delivery point in Oman. DME was launched in June 2007 with a goal to bring about fair and transparent price discovery and efficient risk management to the East of Suez market, considered the fastest growing commodities market and largest crude oil supply and demand corridor in the world. DME Oman Crude Oil is the explicit and sole/official selling price benchmark for Oman (output of 812,000 barrels per day or bpd) and Dubai (output of 54,000 bpd but in decline), which have purportedly been viewed (at least by the DME) as markers for heavy sour ME crude oil grades exported to the Asia-Pacific region. However, due to some limitations associated with inter alia an Oman delivery point and the relatively small output of marker oil fields in Dubai and Oman, the average daily volume (ADV) of DME Oman Crude Oil futures and options contracts are arguably well below the levels reasonably expected for a viable global (or even regional) benchmark, to the point such that, as of the end of 2009, the CME Group elected to write off the $28.6 million carrying value of its investment stake in the DME because it was impaired.    Argus Sour Crude Index (ASCI) is listed at the CME Group's Nymex and the ICE. ASCI is based on three medium sour Gulf of Mexico crudes (Mars, Poseidon and Southern Green Canyon) with a blended average of 29.3° API gravity and 2.03% sulfur targeted for processing by U.S. Gulf Coast refineries. So far, ASCI has been adopted as a benchmark (subject to a myriad of differential adjustments) for spot market sales by Saudi Aramco and Kuwait Petroleum (in 2009) and Iraq's Somo (in 2010). ME crude oils priced against ASCI include Arab Extra Light, Arab Light, Arab Medium, Arab Heavy, Kuwait Export Blend, Basrah Light and Kirkuk. While ASCI might well be more suitable than the light sweet WTI and Brent benchmarks for spot markets and long-term contract arrangements negotiated by ME exporters with U.S. Gulf Coast refineries, ASCI pricing and other methodology (see www.argusmedia.com/methodology) is arguably too cumbersome to generate efficient futures and options contract trading on a wider global scale, especially in connection with ME exports to East of Suez markets, which inter alia include India, Singapore, Hong Kong, China, Taiwan, South Korea and Japan.    Urals is a reference oil brand used as a basis for pricing a principally Russian export oil mixture (specified with 31.8° API gravity and 1.35% sulfur) extracted from the Urals and Volga regions along with lighter crude oils from Western Siberia. It is supplied through the Novorossiysk pipeline system and over the Druzhba pipeline. Urals futures trade on the Russian Trading System (stock exchange), as well as at the CME Group's Nymex, where it is known as Russian Export Blend Crude Oil (REBCO). While Urals are not yet material to the context of this hedging apparatus, they are nonetheless noted due to the planned increase of crude oils to be exported from Russia to China over the newly opened ESPO (Eastern Siberia to Pacific Ocean) pipeline delivering Russian oil to energy hungry China.
In assessing the benchmarks noted above, it becomes clear that, for all intents and purposes, the CME Group's Nymex and the ICE, along with their affiliated exchanges around the world, enjoy a virtual duopoly in the global crude oil futures and options trading arena, as currently shaped. Perhaps more than anything else, this reflects the fact that WTI and Brent are prime light sweet crude oils coveted by highly regulated refineries for their low sulfur content and efficiency in generating high quality refined products. Compared to ME crudes having relatively lower API gravity and higher sulfur content, WTI and Brent are much easier to refine into cleaner gasoline (generally 30 ppm sulfur content) and diesel (generally 10-15 ppm sulfur called ultra-low-sulfur or ULSD) fuels mandated by U.S., West European and other (OECD) government environmental protection agencies (EPAs).
However, that model is not practicable for the rest of the world, where sulfur levels in gasoline and diesel fuels often amount to 500 ppm in major developing countries and several thousand ppm in others. Huge investments would be required for those countries to substantially change over (or build new) refineries to implement cleaner engine, fuel and emission control programs, which could take decades to rationalize and fund. That assumes it would even be feasible or affordable to do so, at all, since the light sweet crude oil phenomenon known as Peak Oil (discussed more fully later herein) lurks in the background. In that event, creating even greater (non-OECD) demand for light sweet crude oil resources would likely cause hyper-inflation on a global scale capable of crashing most, if not all economies. That approach seems foolish, even wasteful, considering that there are much larger (and growing) reserves of relatively heavier and sour crudes that can be tapped well into the future.
WTI and Brent futures and options traded at CME Group's Nymex and the ICE have appealed to Western/OECD buyers and sellers, especially those indulged speculators who have skyrocketed their open interests while creating volatile/spiraling prices via high frequency trading programs that demand trade execution speeds of single digit milliseconds (and headed for microseconds), thereby driving ADV to record heights. WTI and Brent have also been tolerated in the past by ME exporters and their customers wanting to hedge but lacking better alternatives. In doing so, they have resorted to complex Platts and Argus (specialist energy publishers) assessment-based OTC derivatives, often using one or the other as their benchmark but requiring numerous differential adjustments, an overly complex and increasingly inefficient exercise due inter alia to increasingly apparent flaws with these benchmarks.
As mentioned above, the WTI-Brent spread has gone from being relatively tight to a scenario whereby WTI now sells at a considerable (often $10+ per barrel and recently $18+ per barrel) discount to Brent, even though WTI is higher quality crude and it costs extra to ship Brent to the U.S. This anomaly may be attributed to several factors.
First, having WTI's delivery point in Cushing, Okla., is limiting and storage has become problematic, even though capacity has steadily been raised to handle an influx of Canadian crudes coming in via pipeline, along with the new oils produced in North Dakota that have caused aggregate U.S. crude output to just increase for the first time in 23 years. Because it is easier to move oil from major producing regions to Cushing than to move oil from Cushing to refineries (especially U.S. Gulf Coast refineries that also import ME crudes) and consumers, the supply bottle-necks being created there are not expected to go away any time soon. WTI prices are expected to remain in a substantial discount mode (to Brent) and thus be less appealing to traders of ME crude oils.
Further complicating matters, North Sea oil production is declining while European and Asian (especially Chinese) demand for diesel and other distilled products has increased. It should be noted that, whereas WTI tends to generally be more favorable for gasoline products, Brent generally tends to favor production of diesels and other distillates. Thus, added distillate demand for Brent in the face of lower North Sea production has caused supplies to decline and prices to rise. Adding to the fray is the recent turmoil in Africa (especially countries with desirable low sulfur crudes, such as in Libya) and the ME that will not likely be resolved any time soon and could grow worse, all of which currently tends to be reflected more in Brent prices than WTI. The bottom line is that WTI and Brent each have exposed flaws that are causing traders to question their viability as global benchmarks, especially as it relates to crude oils produced in the ME.
It is generally recognized that market prices of so-called “landlocked” crude oil have become increasingly impacted by qualitative factors other than API gravity and sulfur content. This particularly holds true in North America (NA) where production levels have surged in the last few years and are projected to continue to increase. The relative geographic location of producer wells and terminal facilities on one hand versus customer refineries on the other, plus a slew of logistics challenges converging midstream to create bottlenecks, have spawned intermodal permutations, including those pertaining to inter alia pipeline, boat, rail and/or truck solutions, each of which is integral to current market dynamics, thus generating substantial price differentials. Such factors lend support for novel hedging instruments, such as those originally specified in the Parent Application and advanced herein, to help market participants better manage risks of price movements in the future.
The crude oil market in NA is undergoing enormous change. Structural shifts resulting from U.S. light sweet oil shale plays at Eagle Ford (below much of South and East Texas) and Bakken (below parts of Montana, North Dakota and Canada's Saskatchewan province), as well as a growing influx of Canadian oil grades competing for strained (albeit gradually growing) storage and transportation infrastructure in the U.S., have caused significant price dislocations leading to calls for greater market transparency.
According to industry experts, such structural shifts will likely prompt pricing alternatives to West Texas Intermediate (WTI), which until quite recently was NA's singular crude oil benchmark for all intents and purposes. The convergence of such factors as rising Canadian and Bakken production, in tandem with pipeline capacity shortages within the crucial midcontinent to U.S. Gulf Coast (USGC) corridor, have steadily weakened WTI prices the past couple of years versus those for USGC domestic grades and the major international waterborne blend, Brent. Already, there are cases involving the referencing of Eagle Ford sales to Louisiana Light Sweet crude prices.
It remains desirable to provide more alternatives for cases dealing with landlocked crude oil delivered to designated (principally refinery) destinations via intermodal permutations involving inter alia storage terminal, pipeline, boat, rail and/or truck solutions.